System and method for delivering material to a subsea well

ABSTRACT

A system and method for delivering a material from a vessel at a surface facility to a subsea location and into a subsea well are provided. The system generally includes a first-stage pump that is located at the surface facility and is configured to receive the material from the vessel. A tubular member extends from the first-stage pump to the subsea location. A second-stage pump is located at the subsea location and connected to the tubular member. The first-stage pump is configured to deliver the material through the tubular member to the second-stage pump at a first pressure, and the second-stage pump being configured to receive the material from the tubular member and inject the material into the well at a second pressure higher than the first pressure.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Application No.61/138,044, filed Dec. 16, 2008.

BACKGROUND OF THE INVENTION

1. Field of the Invention

This invention relates to the delivery of materials, such as scaleinhibitor chemicals, from a vessel at a surface facility to a subsealocation and into a subsea well, for example, to perform a subsea scalesqueeze treatment in a subsea hydrocarbon well.

2. Description of Related Art

The formation of scale, inorganic crystalline deposits, can occurthroughout the equipment used in a hydrocarbon production operation. Forexample, in one typical situation, the formation of scale can occur as aresult of waterflooding, such as when sea water is injected into a welland mixed with formation water in the well. Scale can also form uponchanges in the supersaturation of solubility of minerals in theformation or produced waters that are caused by pressure and/ortemperature changes. Scale formation can also be increased by nucleationsites, e.g., sand and corrosion. The scale-forming precipitates caninclude various minerals such as calcium carbonate, calcium sulfate,barium sulfate, magnesium carbonate, magnesium sulfate, and strontiumsulfate. For example, sulfate scale deposition is likely to occur whenseawater injection is used to recover deposited hydrocarbons.

Such scaling can occur inside and outside the well, e.g., within tubingsor other equipment through which the production fluids flow from thewell, and represents an important flow assurance problem in the oil andgas industry. In some cases, the scale formation can reduce or preventflow through bores and tubings, prevent proper operation of valves andpumps, and otherwise interfere with the operation of the equipmentassociated with the well.

There are several techniques available to control scale deposition. Forexample, the fluid modification technique includes injecting water ofdifferent composition (e.g. aquifer water or desulfated water) to thereservoir and separating the water from the production stream. The mostcommon technique to prevent and treat scale precipitation is theapplication of chemicals that function as scale inhibitors. Suchchemical inhibitors, or scale inhibitors, may be aqueous based, oilbased, emulsions, micro-encapsulated, porous impregnated pellets, andmultifunctional products (e.g. corrosion/scale inhibitor,asphaltene/scale inhibitor, etc.). Scale inhibitors generally work bypreventing nucleation and crystal growth. Many scale inhibitors can beapplied into the production stream by continuous injection or into thewellbore by a scale squeeze treatment. A typical scale squeeze treatmentfor treating a well with a scale inhibitor includes interrupting theflow of production fluid from the well and injecting the scale inhibitorthrough the well into the reservoir so that the scale inhibitorinteracts with the rock matrix in the reservoir to be adsorbed into theformation and then precipitated onto mineral surfaces. Typically, thesqueeze treatment involves the injection of a preflush solution,followed by the injection of the chemical inhibitor (mainflush), andfinally the injection of an overflush solution. Thereafter, the well isreturned to operation and the scale inhibitor in the reservoir desorbsor dissolves into the fluid in the reservoir, such that the productionfluid contains some scale inhibitor. The scale inhibitor generallyprevents or reduces the deposition of scale from the production fluid inthe tubings and other equipment through which the fluid flows.

Scale inhibitor can be injected into a subsea well from a surfacefacility such as an offshore platform or a floating production andstorage and offloading (FPSO) vessel via production pipelines orflowline (which may include a riser) and associated manifolds thatnormally carry the production fluid upward from the subsea well to thesurface facility. In this case, the flow of production through the riseris stopped. Then, the scale inhibitor is pumped into the top of theriser at the surface facility and through the riser to the subsea welland into the subsea reservoir. Low pump rates for the scale inhibitorare typically required due to a relatively high friction associated withthe production flowline and/or the viscosity of the scale inhibitor,which may increase at the lower temperatures found close to the seabed.In some cases, a large volume of scale inhibitor may be used. Forexample, a typical 15 km-segment of production flowline may have avolume of 5,000 barrels, depending on the diameter, with the entirevolume of the flowline being filled before the scale inhibitor begins toflow into the reservoir. Further, in some cases, the flowline need to beemptied and cleaned by a pigging operation before the chemical inhibitoris pumped into the wellbore in order to avoid pumping debris that existsin the flowline, such as scale, wax, and/or sand, into the formation.

When subsea production of different satellite wells is brought togetherin a manifold or flowline, scale squeeze treatment can become expensive.In this case, it may be necessary to shut down all of the wells even ifonly one well is to be treated since the flowline is to be used todeliver the scale inhibitor. This inconvenience can be avoided byproviding a separate line from each well to a surface productionfacility; however, using dedicated lines may not always be possible dueto engineering restrictions or capital expenditure limitations. In somecases, subsea squeeze treatments are sometimes performed using surfacevessels, e.g., a Diving Support Vessel (DSV) and a flexible lineattached to the subsea manifold. Subsea squeeze treatments have alsobeen performed by placing encapsulated inhibitors into the wellhead. Inthat case, a Diving Support Vessel can transport the capsules, whichfall down by their own weight through a flexible riser, into the sump.Diffusion of the scale inhibitor takes place due to difference inconcentration gradients.

While such operations have been successfully used for subsea scalesqueeze treatments, there exists a continued need for improved systemsand methods for delivering materials, such as chemicals for a scalesqueeze treatment, to a subsea well. The system and method should becapable of being used with a passage that is not defined by a riser,e.g., so that a subsea scale squeeze treatment can be performed withoutemptying the production fluid from the riser or reversing the flow offluid in the riser, and should be capable of use in systems that includeseveral wells and/or trees attached to a common production flowline.

SUMMARY OF THE INVENTION

The embodiments of the present invention generally provide systems andmethods for delivering a material from a vessel at a surface facility toa subsea location and into a subsea well, such as for delivering one ormore scale squeeze treatment chemicals adapted to inhibit scaling via anumbilical or other tubular member to a subsea well for a subsea scalesqueeze treatment of the well. According to one embodiment, the systemincludes a first-stage pump located at the surface facility andconfigured to receive the material from the vessel. A tubular memberextends from the first-stage pump to the subsea location. A second-stagepump is located at the subsea location and connected to the tubularmember. For example, the second-stage pump can be disposed on theseafloor and/or as part of a tree at a head of the subsea well. Thefirst-stage pump is configured to deliver the material through thetubular member to the second-stage pump at a first pressure, and thesecond-stage pump is configured to receive the material from the tubularmember and inject the material into the well at a second pressure higherthan the first pressure.

In some cases, the tubular member can be a flexible tube formed of athermoplastic material and/or a flexible umbilical that defines a firsttubular passage for receiving and delivering the material, and a secondtubular passage having at least one conductive cable for communicatingbetween the surface facility and the subsea location. The conductivecable can be configured to provide at least one of an electrical signalfor controlling the operation of the second-stage pump and electricalpower for powering the operation of the second-stage pump.

According to another embodiment, the present invention provides a methodof delivering a material from a vessel at a surface facility to a subsealocation and into a subsea well. The method includes operating afirst-stage pump located at the surface facility to pump the materialfrom the vessel through a tubular member extending from the first-stagepump to the subsea location, and operating a second-stage pump at thesubsea location and connected to the tubular member to inject thematerial from the tubular member into the well. For example, the methodcan include providing the second-stage pump at the seafloor and/or aspart of a tree at a head of the subsea well. The operation of thefirst-stage pump and the second-stage pump can include injecting a scalesqueeze treatment chemical into the well to thereby perform a scalesqueeze treatment of the well and inhibit scaling in the well and/or theriser, production pipeline, flowlines, or other equipment downstream ofthe well.

In some cases, a flexible tube formed of a thermoplastic material or aflexible umbilical can be provided as the tubular member, and thefirst-stage pump can be operated to pump the material through a firsttubular passage of the umbilical. The umbilical can be provided with atleast one conductive cable in the umbilical in communication with thesurface facility and the subsea location. An electrical signal can becommunicated from the surface facility to the subsea location via theconductive cable to control the operation of the second-stage pump,and/or electrical power can be provided from the surface facility to thesubsea location via the electrically conductive cable to power theoperation of the second-stage pump.

BRIEF DESCRIPTION OF THE DRAWINGS

Having thus described the invention in general terms, reference will nowbe made to the accompanying drawings, which are not necessarily drawn toscale, and wherein:

FIG. 1 is an elevation view schematically illustrating a system fordelivering material from a surface facility to a subsea location andinto a subsea well according to one embodiment of the present invention;

FIG. 2 is a cross-sectional view schematically illustrating an umbilicalaccording to one embodiment of the present invention;

FIG. 3 is an elevation view illustrating a system for deliveringmaterial from a floating production facility to a subsea location andinto a subsea well according to one embodiment of the present invention;

FIG. 4 is an elevation view illustrating a system for deliveringmaterial from a service vessel to a subsea location and into a subseawell according to another embodiment of the present invention; and

FIG. 5 is an elevation view illustrating a system for deliveringmaterial from a service vessel to a subsea location and into a subseawell according to another embodiment of the present invention.

DETAILED DESCRIPTION OF THE INVENTION

The present invention now will be described more fully hereinafter withreference to the accompanying drawings, in which some, but not allembodiments of the invention are shown. Indeed, this invention may beembodied in many different forms and should not be construed as limitedto the embodiments set forth herein; rather, these embodiments areprovided so that this disclosure will satisfy applicable legalrequirements. Like numbers refer to like elements throughout.

Referring now to the drawings and, in particular, to FIG. 1, there isschematically shown a system 10 for delivering a material, such aschemicals for performing a scale squeeze treatment to a subsea well 12.The system 10 generally includes a plurality of pumping units 14, 16 ina multi-stage pumping arrangement for delivering the material from oneor more vessels 18 located at a surface facility 20 to a subsea location22 via a tubular member 24 and injecting the material into the well 12.

The surface facility 20 can be any type of surface unit, such as anoffshore platform or oil rig of any type. The vessel 18 can include oneor more storage tanks mounted on the surface facility 20 or containersthat are brought by ship or otherwise to the facility 20 and fluidlyconnected to the facility 20 so that the material in the vessel 18 canbe received by a first-stage pumping unit 14 located at the surfacefacility 20.

The first-stage pumping unit 14 receives the material and pumps thematerial through the tubular member 24, such as an umbilical, thatextends from the surface facility 20 to a subsea location 22. Inparticular, as shown in FIG. 1, the tubular member 24 can extend to asecond-stage pumping unit 16 located at the subsea location 22, e.g., ator proximate to the seafloor 26. The tubular member 24 defines one ormore passages for the flow of the material. The first-stage pumping unit14 delivers the material through the tubular member 24 and to thesecond-stage pumping unit 16 at a first pressure, typically higher thanatmospheric pressure but insufficient for delivering the material intothe well 12 and reservoir. It is appreciated that the pressure of thematerial may decrease from the inlet 28 of the tubular member 24 at thefirst-stage pumping unit 14 to the outlet 30 of the tubular member 24 atthe second-stage pumping unit 16. For example, the material can bestored in the vessel 18 at approximately atmospheric pressure, thefirst-stage pumping unit 14 can raise the pressure to a higher pressureto deliver the material through the tubular member 24, and the materialcan be provided to the second-stage pumping unit 16 at an even higherpressure.

The first-stage pumping unit 14 can be powered by a power source 32,e.g., an electric or hydraulic power source. The operation of the powersource 32 and the first-stage pumping unit 14 can be controlled by acontroller 40, e.g., a computer device configured to receive manualinputs from a human operator and/or operate according to a program ofpredetermined and defined commands and parameters. The controller 40 andthe power source 32 can also be used to control and/or power the othercomponents of the system 10, including the second-stage pumping unit 16.In some cases, the controller 40 can be a high pressure interventioncontrol system unit.

The second-stage pumping unit 16 at the subsea location 22 is connectedto the tubular member 24 and receives the material from the first-stagepumping unit 14 via the tubular member 24. The second-stage pumping unit16 raises the pressure of the material and injects the material into thewell 12 at a second pressure that is higher than the first pressureachieved by the first-stage pumping unit 14.

The multi-stage pumping system 10 of the present invention can providethe material to the well 12 with sufficient pressure for injection,while providing a relatively limited pressure of the material throughoutthe rest of the system 10. For example, if the first-stage pumping unit14 were operated without the second-stage pumping unit 16, a greaterpressure would be required in the tubular member 24 to providesufficient pressure at the subsea location 22 for injection of thematerial into the well 12. Typically, the first-stage pumping unit 14would be required to provide the material with a pressure that is atleast as great as the sum of the pressure drop that occurs in thetubular member 24 between the inlet 28 and outlet 30 and the pressurerequired for injection into the subsea well 12. In some cases, e.g.,where the tubular member 24 is an umbilical or a low-pressure hose ortube with a relatively narrow diameter, and/or the tubular member 24 isa long member for deepwater applications or otherwise, the pressure dropalong the length of the tubular member 24 can be relatively great. Insuch cases, the required pressure at the inlet 28 of the tubular member24 for overcoming both the pressure drop through the tubular member 24and the pressure required at the subsea location 22 for injection intothe well 12 can exceed the strength of the tubular member 24. Thus, fora single-stage pump system, it may be required to provide a tubularmember 24 with a high strength to withstand the high pressures requiredand/or to provide a tubular member 24 with a relatively large diameterso that the pressure drop therethrough is not excessively high.

On the other hand, the second-stage pumping unit 16, which is providedat the subsea location 22 and downstream of the tubular member 24, canbe used to raise the pressure to a level sufficient for injection intothe well 12 so that the pressure in the tubular member 24 can be limitedto a level that is within the operating limits of the tubular member 24.In this way, the pressure of the material provided by the first-stagepumping unit 14 to the tubular member 24 can be sufficient to overcomethe pressure drop through the tubular member 24 but less than the sum ofthe pressure drop through the tubular member 24 and the pressurerequired at the subsea location 22 for injection into the well 12. Thus,it may be sufficient to use a tubular member 24 with a relatively lowerstrength and/or a relatively small diameter. Even in deepwaterapplications where the tubular member 24 is long, an umbilical can havethe sufficient strength and size to accommodate the flow of the materialand the pressure required for maintaining the flow of the materialtherethrough. For example, the tubular member 24 can be structured tohave a strength that is greater than the pressure drop that occurs inthe tubular member 24 so that the tubular member 24 can withstand thepressure required to deliver the material therethrough; however, thetubular member 24 can be structured to have a strength that is less thanthe sum of the pressure drop that occurs in the tubular member and thepressure required for injection into the subsea well 12. In particular,in some cases, the tubular member 24 can be structured to provide aburst strength of 15,000 psi or less, and the material can be providedat a maximum pressure in the tubular member 24 that is between 3,000 psiand 5,000 psi.

For example, the tubular member 24 of FIG. 1 is a flexible umbilical,and the cross-section of the umbilical is further illustrated in FIG. 2.The umbilical is a composite cable that includes an outer sheath 42 thatcontains a plurality of longitudinal members or functional components,such as tubes or hoses formed of thermoplastics or steel or othermetals, electrically or optically conductive cables, strength members,and the like. For example, as shown in FIG. 2, the umbilical includeshollow, cylindrical tubes 44 a, 44 b, 44 c that define tubular passages46 for the delivery of chemicals or other materials between the surfacefacility 20 and the subsea location 22. For example, one or more of thetubular passages 44 a, 44 b, 44 c can be used for the delivery of thescale inhibitors during a subsea scale squeeze operation or for thedelivery of hydraulic fluids or the like for other operations. Theumbilical also includes conductive communication cables 48 that can beformed of electrical or optical conductors, such as solid or twistedcopper or aluminum cables or fiber optic cables. The communicationcables can be used for communication of control signals, fortransmission of electrical power, and/or for the communication ofinformation, such as information collected by sensors or other devicesat the subsea location 22. The cables can be contained in sheaths 50 ofplastic or other protective materials. Strength members 52 can be formedof steel, composite materials, or the like and used to increase thestrength and/or stiffness of the umbilical. In addition, other membersor materials can be provided within the outer sheath 42. For example, insome cases, the space 54 between the various members in the sheath 42can be filled with plastic or other materials to increase the strength,buoyancy, rigidity, or seal of the umbilical.

It is appreciated that the umbilical shown in FIG. 2 is an exemplarytubular member 24 that can be used in the system 10 of the presentinvention, and other tubular members can also be used, includingumbilicals of various sizes, configurations, and materials. For example,in some cases, the tubular member 24 can be a flexible tube formed of apolymer, a thermoplastic material, a reinforced composite material, orthe like. The tubular member can be a dedicated device (or a dedicatedfluid passage in a composite umbilical or other device) that is used fordelivery of the material to the well but that is not used for deliveryof production fluids from the well, and the tubular member (or thededicated passage) can be sized accordingly, e.g., smaller than atypical riser that delivers production fluids from a subsea well to afloating production facility. For example, in some cases, the internaldiameter of the fluid passage of the tubular member that is used fordelivering the material to the well can be between about ¼ inch and 4inches, such as about such as about ½ inch, 1 inch, or 2 inches, 3inches, or 4 inches. For example, the first tubular passage 44 a of theumbilical shown in FIG. 2 can have a diameter of about ¼ inch or ½ inchand can be used for delivering the material to the well 12. Forsituations where a greater volume of material is to be delivered to thewell 12, the tubular member 24 can be a larger hose, such as a 3- or4-inch diameter hose formed of a composite material, such as athermoplastic matrix material with a synthetic aramid or otherreinforcement material.

The multi-stage pump system 10 of the present invention is illustratedwith two pumping units 14, 16 in FIG. 1, and each pumping unit 14, 16typically includes one pump, but additional pumps or pumping units 14,16 can be provided in other embodiments. For example, additional pumpscan be located at the surface facility 20, subsea location 22, ortherebetween. Additional pumps can be configured in parallel with theillustrated pumping units 14, 16 to provide increased pumping capacityor redundancy, and/or additional pumps can be provided in series withthe illustrated pumping units 14, 16 to successively raise the pressureof the material along the flow path of the material. Some or all of thepumping units 14, 16 can include filters to prevent the delivery ofsolids and particles and thereby prevent the injection of such solidsand particles into the well 12 and the reservoir formation. Further,each pumping unit 14, 16 can be adapted to selectively pump chemicalsand/or to mix chemicals if necessary.

Sensors 60 can be provided for monitoring relevant operationalparameters, such as pressure, temperature, flow, viscosity, or the like.Such sensors 60 can be provided in the vessel 18, pumping units 14, 16,tubular member 24, or elsewhere throughout the system 10. Signals fromthe sensors 60 can be communicated to a central control device, such asthe controller 40, which can then adjust the system parameters accordingto the conditions sensed by the sensors 60, e.g., by adjusting valvesthroughout the system 10, by controlling the operational state and speedof the pumping units 14, 16, and by controlling the operation of heatersor other equipment throughout the system 10. The controller 40 can alsoreceive other signals from sensors installed inside the tree or withinthe wellbore. Sensors at the subsea location 22 are typically configuredto communicate with a surface location, e.g., by sending signals to thecontroller 40 via the umbilical. If the controller 40 is not located atthe same surface facility 20 where the umbilical is connected, then anadditional communication link, such as a wired or wireless connection,can be provided between the surface facility 20 and the controller 40.

FIG. 3 illustrates a system 10 according to another embodiment of thepresent invention in which the second-stage pumping unit 16 is providedas an integral part of a subsea tree 62. As illustrated, the surfacefacility 20 is a floating production facility, such as an offshoreplatform at the ocean surface 34. The first-stage pumping unit 14 islocated in the floating production facility 20. The tubular member 24 isan umbilical and connects the first-stage pumping unit 14 to thesecond-stage pumping unit 16, which is located on the seafloor 26 aspart of a subsea tree 62, which generally controls the flow of fluidsinto and out of the well 12. The second-stage pumping unit 16 can belocated proximate to, but separate from, the tree 62. Alternatively, asshown in FIG. 3, the second-stage pumping unit 16 can be an integralpart of the tree 62, i.e., part of a single piece of equipment that isdeployed as one unit. In either case, the umbilical can be connected tothe second-stage pumping unit 16 via a subsea umbilical terminationassembly 68. Further, as illustrated, the umbilical can be fluidlyconnected to additional segments that extend to other wells or the like.

In another embodiment, shown in FIG. 4, the surface facility 20 is aservice vessel such as an FPSO. The service vessel can include thefirst-stage pumping unit 14, the vessel 18 for providing the scaleinhibitor or other materials for injection, the controller 40, and thepower source 32, so that the service vessel can provide the material forthe injection operation. In addition, the service vessel can be used todeploy the umbilical or other tubular member 24. In this regard, a winchapparatus 64 can be used to control the unreeling of a cable 66 attachedto the umbilical termination assembly 68 that is connected to theumbilical. As the cable 66 is unreeled from the service vessel, theumbilical termination assembly 68 can be lowered to the subsea location22, thereby deploying the umbilical, which can also be unreeled from theservice vessel, e.g., from reel 70. A remote-operated vehicle (ROV) orother submersible control device can be used to assist in connecting theumbilical termination assembly 68 to the second-stage pumping unit 16that is attached to, or part of, the subsea tree 62. Alternatively, theumbilical termination assembly 68 can be adapted to attach itself to thesecond-stage pumping unit 16 and/or the tree 62, e.g., autonomously orunder operator control. In some embodiments, the umbilical terminationassembly 68 can include additional equipment to assist in attaching theumbilical termination assembly 68 to the second-stage pumping unit 16and/or the tree 62, such as a global position system (GPS) device, oneor more cameras, thrusters for controlling the location and orientationof the umbilical termination assembly 68, electric and/or hydraulicsystems, and the like. As shown in FIG. 4, buoyancy devices 72 can beattached at a plurality of positions along the length of the tubularmember 24 so that the buoyancy devices 72 are deployed to differentdepths when the tubular member 24 is generally vertically oriented. Thebuoyancy devices 72 generally reduce the forces exerted throughout thetubular member 24 and on the connections of the tubular member 24 due tothe weight of the tubular member 24.

In another embodiment, shown in FIG. 5, the second-stage pumping unit 16is connected to the tubular member 24 and is deployed from the surfacefacility 20 with the tubular member 24. For example, as illustrated, thetubular member 24 can be an umbilical, and the umbilical and the cable66 can be connected to the second-stage pumping unit 16 before beingdeployed. The second-stage pumping unit 16 can be deployed with theumbilical by using the winch apparatus 64 to control the unreeling ofthe cable 66. As the cable 66 is unreeled from the service vessel, thesecond-stage pumping unit 16 can be lowered to the subsea location 22,thereby deploying the umbilical, which is also unreeled from the servicevessel. The location and configuration of the second-stage pumping unit16 can be controlled using a remote-operated vehicle (ROV) or othersubmersible control device or by using additional equipment providedwith the second-stage pumping unit 16, such as a global position system(GPS) device, one or more cameras, thrusters for controlling thelocation and orientation of the umbilical termination assembly 68,electric and/or hydraulic systems, and the like.

With the tubular member 24 configured to connect the first- andsecond-stage pumping units 14, 16, the system 10 can be used toselectively inject materials into the subsea well 12. In a typicalinjection operation, the first-stage pumping unit 14 operates at arelatively lower pressure, and the second-stage pumping unit 16 operatesat a relatively higher pressure. The pumping units 14, 16 can provide avariable rate of flow of the materials into the well 12, and the system10 can selectively pump a series of materials into the well 12. Forexample, different chemicals for performing a preflush, mainflush, andoverflush operation can be stored in the vessel(s) 18. The differentchemicals can be delivered by the system 10 to the well 12 successivelyor simultaneously. In some cases, the vessel(s) 18 can include heatingdevices, such as resistance heaters or heat exchangers, to adjust thetemperature of the chemicals, e.g., to heat the chemicals and therebyincrease the flow rate of the chemicals through the tubular member 24.

The tubular member 24 can be configured to communicate between thepumping units 14, 16, e.g., in cases where the tubular member 24 is anumbilical. Thus, the umbilical can transport chemicals for a scalesqueeze treatment operation as well as communicating signals fromsensors at each end of the umbilical, communicating control signals,e.g., for controlling the operation of the pumping units 14, 16, and/orcommunicating power, e.g., for operating the pumping units 14, 16. Moreparticularly, signals from sensors 60 at the subsea location 22 can becommunicated via the umbilical to the controller 40 at the surfacefacility 20, and the controller 40 can provide via the umbilical eitheror both of operating power for operating the second-stage pumping unit16 and operating commands for controlling the operation of thesecond-stage pumping unit 16 and thereby controlling the injection ofmaterials for the subsea scale squeeze treatment. Communication of suchsignals through the tubular member 24 can be performed using electricalsignals through electrically conductive elements (e.g., copper wires) ofthe tubular member 24 or using optical signals through opticallyconductive elements (e.g., fiber optics) of the tubular member 24. Insome cases, the second-stage pumping unit 16 can be powered by thesubsea tree 62 or via a flying lead that is connected to the subseaumbilical termination assembly 68.

In some cases, the amount of material, such as chemical scale inhibitor,that is used is relatively less than that which would otherwise berequired in a conventional method of delivering the material to thesubsea well 12 via a production pipeline or flowline, e.g., because thediameter and the volume of the tubular member 24 can generally be lessthan a production pipeline by virtue of the multiple-stage pumpingarrangement of the present invention. Further, if the tubular member 24is an umbilical or other relatively low-pressure, low-diameter memberthat is not used for delivering production fluids from the well 12, theamount of debris and solids that are pumped into the wellbore duringinjection into the well 12 can be reduced. That is, while a pipeline orflowline typically contains such debris and solids, which may beinjected into the well 12 if the pipeline or flowline is used forinjecting fluids into the well 12, such injection of debris and solidscan generally be avoided by using a separate tubular member 24 forinjecting the scale inhibitor or other materials into the well 12. It isalso appreciated that, by using a separate tubular member 24 forinjection of the material, downtime associated with the injection ofmaterials through the production pipeline or flowline can generally beavoided or reduced.

Many modifications and other embodiments of the invention set forthherein will come to mind to one skilled in the art to which thisinvention pertains having the benefit of the teachings presented in theforegoing descriptions and the associated drawings. Therefore, it is tobe understood that the invention is not to be limited to the specificembodiments disclosed and that modifications and other embodiments areintended to be included within the scope of the appended claims.Although specific terms are employed herein, they are used in a genericand descriptive sense only and not for purposes of limitation.

What is claimed is:
 1. A system for delivering a material from a vesselat a surface facility to a subsea location and into a subsea well, thesystem comprising: a first-stage pump located at the surface facilityand configured to receive the material from the vessel; a tubular memberextending from the first-stage pump to the subsea location; and asecond-stage pump at the subsea location and connected to the tubularmember, the first-stage pump being configured to deliver the materialthrough the tubular member to the second-stage pump at a first pressure,and the second-stage pump being configured to receive the material fromthe tubular member and inject the material into the well at a secondpressure higher than the first pressure.
 2. A system according to claim1 wherein the tubular member is a flexible umbilical, the umbilicaldefining a first tubular passage for receiving and delivering thematerial, and a second tubular passage having at least one conductivecable for communicating between the surface facility and the subsealocation.
 3. A system according to claim 2 wherein the conductive cableis configured to provide at least one of an electrical signal forcontrolling the operation of the second-stage pump and electrical powerfor powering the operation of the second-stage pump.
 4. A systemaccording to claim 1 wherein the second-stage pump is disposed on theseafloor.
 5. A system according to claim 1 wherein the second-stage pumpis disposed as part of a tree at a head of the subsea well.
 6. A systemaccording to claim 1 wherein the vessel is configured to provide a scalesqueeze treatment chemical adapted to inhibit scaling and thesecond-stage pump is configured to inject the chemical into the well toperform a scale squeeze treatment of the well.
 7. A system according toclaim 1 wherein the tubular member is a flexible tube formed of athermoplastic material.
 8. A method of delivering a material from avessel at a surface facility to a subsea location and into a subseawell, the method comprising: operating a first-stage pump located at thesurface facility to pump the material from the vessel through a tubularmember extending from the first-stage pump to the subsea location; andoperating a second-stage pump at the subsea location and connected tothe tubular member to inject the material from the tubular member intothe well.
 9. A method according to claim 8, further comprising providinga flexible umbilical as the tubular member, wherein operating thefirst-stage pump comprises pumping the material through a first tubularpassage of the umbilical, and further comprising providing at least oneconductive cable in the umbilical in communication with the surfacefacility and the subsea location.
 10. A method according to claim 9,further comprising communicating an electrical signal from the surfacefacility to the subsea location via the conductive cable to control theoperation of the second-stage pump.
 11. A method according to claim 9,further comprising providing electrical power from the surface facilityto the subsea location via the electrically conductive cable to powerthe operation of the second-stage pump.
 12. A method according to claim8 wherein operating the first-stage pump comprises providing thematerial to the tubular member at a pressure that is greater than apressure drop that occurs through the tubular member and less than a sumof the pressure drop that occurs through the tubular member and apressure required for injecting the material into the well.
 13. A methodaccording to claim 8, further comprising providing the second-stage pumpat the seafloor.
 14. A method according to claim 8, further comprisingproviding the second-stage pump as part of a tree at a head of thesubsea well.
 15. A method according to claim 8 wherein operating thefirst-stage pump and the second-stage pump comprises injecting a scalesqueeze treatment chemical into the well to thereby perform a scalesqueeze treatment of the well and inhibit scaling in the well.
 16. Amethod according to claim 8, further comprising providing a flexibletube as the tubular member, the flexible tube being formed of athermoplastic material.